Fields of Disclosure
The disclosure relates generally to the field of fluid separation. More specifically, the disclosure relates to the cryogenic separation of contaminants, such as acid gas, from a hydrocarbon.
Description of Related Art
This section is intended to introduce various aspects of the art, which may be associated with the present disclosure. This discussion is intended to provide a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
The production of natural gas hydrocarbons, such as methane and ethane, from a reservoir oftentimes carries with it the incidental production of non-hydrocarbon gases. Such gases include contaminants, such as at least one of carbon dioxide (“CO2”), hydrogen sulfide (“H2S”), carbonyl sulfide, carbon disulfide and various mercaptans. When a feed stream being produced from a reservoir includes these contaminants mixed with hydrocarbons, the stream is oftentimes referred to as “sour gas.”
Many natural gas reservoirs have relatively low percentages of hydrocarbons and relatively high percentages of contaminants. Contaminants may act as a diluent and lower the heat content of hydrocarbons. Additionally, in the presence of water some contaminants can become quite corrosive.
It is desirable to remove contaminants from a stream containing hydrocarbons to produce sweet and concentrated hydrocarbons. Specifications for pipeline quality natural gas typically call for a maximum of 2-4% CO2 and ¼ grain H2S per 100 scf (4 ppmv) or 5 mg/Nm3 H2S. Specifications for lower temperature processes such as natural gas liquefaction plants or nitrogen rejection units typically require less than 50 ppm CO2.
The separation of contaminants from hydrocarbons is difficult and consequently significant work has been applied to the development of hydrocarbon/contaminant separation methods. These methods can be placed into three general classes: absorption by solvents (physical, chemical and hybrids), adsorption by solids, and distillation.
Separation by distillation of some mixtures can be relatively simple and, as such, is widely used in the natural gas industry. However, distillation of mixtures of natural gas hydrocarbons, primarily methane, and one of the most common contaminants in natural gas, carbon dioxide, can present significant difficulties. Conventional distillation principles and conventional distillation equipment are predicated on the presence of only vapor and liquid phases throughout the distillation tower. The separation of CO2 from methane by distillation involves temperature and pressure conditions that result in solidification of CO2 if pipeline or better quality hydrocarbon product is desired. The required temperatures are cold temperatures typically referred to as cryogenic temperatures.
Certain cryogenic distillations can overcome the above mentioned difficulties. These cryogenic distillations provide the appropriate mechanism to handle the formation and subsequent melting of solids during the separation of solid-forming contaminants from hydrocarbons. The formation of solid contaminants in equilibrium with vapor-liquid mixtures of hydrocarbons and contaminants at particular conditions of temperature and pressure takes place in a controlled freeze zone section.
A frozen solids accumulation and melt (A&M) section of the controlled freeze zone region of a distillation tower may be designed to: (a) pass vapor from the section below the A&M section to the section above; (b) accumulate the solid contaminants; (c) melt the accumulated solid contaminants; and (d) remove the melted contaminants. FIGS. 1 and 2 show a typical design for an A&M section 1, where FIG. 1 illustrates an elevational view of the A&M and FIG. 2 illustrates a cross-section view of the A&M. The A&M section 1 is disposed within the walls 2 of a controlled freeze zone section 3. The A&M section 1 is comprised of a plurality of vapor risers 4 and one or more coils of tubing 5 or heating elements arranged around the vapor risers 4. Ideally, frozen particulates fall into the interstitial space between the coils of tubing 5 and accumulate over time. At a set time, a heating medium flows through the coils of tubing 5 to melt the accumulated frozen mass. The melted mass then exits A&M section 1.
Within the confines of the design depicted in FIGS. 1 and 2, depending on the operating conditions and physical characteristics of the frozen particles, such particles may not fall into and accumulate in the interstitial spacing between the tube coils. Rough surfaces and surface imperfections serve as a nucleation points for particle deposition and promote agglomeration with additional particles. Frozen particles may accumulate on, but not limited to: (a) the walls of the tubes in the coils of tubing 5; (b) the walls of the vapor risers 4; (c) the covers of the vapor risers 4; (d) surface imperfections on the wall 2 of the A&M section 1; and (e) other internal structures in the controlled freeze zone section 3 immediately above the A&M section 1. If not in contact with or exposed to the coils of tubing, the accumulated frozen mass may be effectively removed from the melting process, reducing its effectiveness.
Therefore, a need exists for improved technology to effectively melt the accumulated frozen mass in a controlled freeze zone unit. There is also a need for improved technology in a controlled freeze zone unit that reduces uneven collection and agglomeration of frozen particulates within the desired accumulation region. Further, there is a need for improved technology in a controlled freeze zone unit that reduces frozen particulate accumulation outside of the designated region.